This invention relates to well treatment fluids comprising amphoteric surfactants and methods of using those fluids to treat and/or fracture subterranean formations.
Hydraulic fracturing is used by the petroleum industry to increase well productivity or injectivity by creating highly conductive paths some distance from the well bore in a formation. The fracturing is created by injecting suitable fluids into the well under pressure until the reservoir rock fractures.
Water soluble polymers have been extensively used in the petroleum industry to enhance the productivity of oil and gas operations. These polymers have been used in drilling fluids, gravel pack fluids, fluid loss circulation, and hydraulic fracturing. These i. techniques have one priority in common and that is the ability of the water soluble polymer to suspend solids. Common water soluble polymers used are hydroxy ethyl cellulose (HEC), xanthan gum, crosslinked guar and its derivatives. HEC is typically used for low temperature applications due to its high decrease in viscosity with increase in temperature. Xanthan gum has superior suspension properties over HEC especially at higher temperatures, but because of its higher molecular weight, xanthan gum tends to filter out at the formation face at low permeabilities (less than 50 md (5xc3x9710xe2x88x928 m2)). This is adequate for drill-in fluids since acid and/or oxidizers are subsequently used to remove most of the polymer damage. Xanthan gum is not typically used for hydraulic fracturing because of the difficulty in placing the acid over the proppant if filtered out. If the permeability is high enough for the xanthan gum to flow through the formation, the polymer has a tendency to impart formation damage. Therefore, crosslinked guar and its derivatives have been developed that minimize formation invasion by incorporating a filter cake. Breakers are typically added to the fluid so that they react within the filter cake to allow ease of the oil and gas during flowback. However, the filter cake is typically broken in fragments and is entrained by the proppant, thereby reducing well conductivity.
U.S. Pat. No. 3,960,736 discloses an acid type breaker for lowering the viscosities of polysaccharide solutions using organic esters. In the examples, the pH needs to be lowered to about 3 using an ester to reduce viscosity by 50% within 4 hours from the solution without an ester. If the pH is about 5 to 6, then a longer time of about 24-72 hours are required. In acid soluble formations containing limestone this breaking time cannot be predicted since acid hydrolyzed ester can react with the limestone instead of the polysaccharide.
U.S. Pat. No. 5,551,516 discloses cationic surfactants based upon quaternary ammonium halide salts. The compositions appear to have stable fluid viscosities of about 225xc2x0 F. (107xc2x0 C.) and are disclosed to be useful in fracturing. However they fail to address the problems that can occur, like formation damage and ease of flowback by reducing the viscosity after fracture is completed.
WO 99/24693 discloses viscoelastic surfactant fracturing fluids comprising an aqueous medium, an inorganic water soluble salt, a surfactant (anionic, non-ionic or hydrotropic), and optional organic alcohols. Although not mentioned in the disclosures, WO 99/24693""s examples produce acidic solutions having a pH less than 2.0. Flowing these types of fluids through Berea sandstone cores produces extreme formation damage (more than 90% damage). The acidic viscous solution reacts with acid soluble materials within the core. Once dissolved the acid insoluble materials are released. Then the viscous solution carries these materials within the core and plugs the pore throats. These problems render WO 99/24693""s compositions commercially non-viable.
The inventor herein has discovered that WO 99/24693""s acidic solutions can be made neutral or basic without substantially affecting its viscosity. Although this imparts less formation damage, removing the viscous solution is difficult and requires days or weeks of flushing to obtain 20% damage. Further the inventor herein has discovered that providing a breaker to substantially lower the viscosity of the fluid once the fracturing is completed can prevent the proppant from flowing back to surface once the well is put on production. This prevents damage to equipment, lines, and values due to the abrasiveness of the proppant.
The present invention provides fluid stable compositions having stable viscosities above 300xc2x0 F. (149xc2x0 C.) that are also pH sensitive so that the fluids may be easily treated to reduce the viscosity and obtain easier flowback and less formation damage.
This invention relates to well treatment fluids comprising amphoteric surfactant(s), water, non-aqueous solvent(s) and optionally an acid forming compound (provided that if the acid forming compound is present a hydrophilic alcohol may also be optionally present.) and methods of using those fluids to treat or fracture subterranean formations.
This invention relates to well treatment fluids comprising:
(a) one or more amphoteric surfactants, preferably present at about 1 to about 50 weight percent, more preferably 1 to 40 weight percent, more preferably about 2 to about 30 weight percent, even more preferably at about 5 to about 25 weight percent based upon the weight of the fluid;
(b) water, preferably present at about 30 to about 95 weight percent, more preferably about 40 to about 90 weight percent, even more preferably at about 50 to about 85 weight percent, based upon the weight of the fluid;
(c) non-aqueous solvent(s), preferably present at about 0.1 to about 25 weight percent, more preferably about 0.5 to about 20 weight percent, even more preferably at about 1 to about 15 weight percent, based upon the weight of the fluid; and
(d) optionally, an acid forming compound preferably present at about 0.005 to about 10 weight percent, more preferably about 0.01 to about 5 weight percent, even more preferably at about 0.05 to about 2 weight percent, based upon the weight of the fluid, provided that when the acid forming compound is present a hydrophilic alcohol (i.e. preferably an alcohol that retards the hydrolysis reaction of the acid forming compound) may also be present at about 0.1 to about 15 weight percent, more preferably about 0.5 to about 12 weight percent, even more preferably at about 1 to about 8 weight percent, based upon the weight of the fluid.
In a preferred embodiment the amphoteric surfactant is present at about 8 weight percent to about 10 weight percent and the solvent is present at about 5 weight percent to about 7 weight percent.
In a preferred embodiment the water may be freshwater or salt water. In another embodiment the water may be seawater or water that has had a salt added to it. Such salts include potassium chloride, sodium chloride, cesium chloride, ammonium chloride, calcium chloride, magnesium chloride, sodium bromide, potassium bromide, cesium bromide, calcium bromide, zinc bromide, sodium formate, potassium formate, cesium formate, sodium acetate and mixtures thereof. In one embodiment the salt is present at up to 4 weight % and the salt water is used to treat the formation prior to introducing the fluid into the formation.
In another embodiment the pH of the fluid is, or is adjusted to, about 6.5 or more, more preferably 7 or more, more preferably 8 or more, more preferably 9 or more, more preferably between 9 and 15, more preferably between 7.5 and 9.5. The pH may be adjusted by any means known in the art, including adding acid or base to the fluid, bubbling CO2 through the fluid and the like.
In another embodiment the fluid further comprises a hydrophobic organic alcohol, preferably a C4 to C20 hydrophobic alcohol, preferably C4 to C20 linear alcohols, preferably an alcohol selected from the group consisting of diethanol, propanol, butanol, pentanol, heptanol, nonanol, decanol, dodecanol, phenol, propanol alcohol ethers, butanol alcohol ethers, ethylbenzyl alcohol, 2-ethyl-1-hexanol, 1-octanol, 2-octanol, and mixtures thereof.
In a preferred embodiment the hydrophilic alcohol is one that is soluble or is miscible with the acid forming compound. Examples of preferred hydrophilic alcohols include methanol, ethanol, propanol, butanol, ethylene glycol, propylene glycol, poly ethylene glycol, poly propylene glycol, dihydric alcohol, poly hydydric alcohol and sugar alcohols and mixtures thereof.
In a preferred embodiment the amphoteric surfactant is lecithin obtained from soybeans and is composed mostly of phosphatidylcholine, phosphatidylethanolamine, and phosphatidylinositol. In another preferred embodiment the amphoteric surfactant is chemically or enzymatically modified. The lecithin may be natural or synthetic lecithin. For more information on lecithin and its many variants, please see the Kirk-Othmer Encyclopedia of Chemical Technology, 4th ed. Volume 15, pages 192-210, John Wiley and Sons, 1995. Lecithins Sources, Manufacture and Uses, by Bernared F. Szuhaj, American Oil Chemist"" Society, 1985 and Lecithins, by Bernard F. Szuhaj and Gary R. List, American Oil Chemists"" Society, 1985.
In another embodiment the non-aqueous solvent comprises one or more hydrocarbons and/or halogenated hydrocarbons, preferably aliphatic or aromatic hydrocarbons, more preferably an alcohol, a mineral oil, soybean oil, corn oil, a fatty acid, a glycol ether, an ether or a mixture thereof. In a particularly preferred embodiment the solvent is a linear, branched or cyclic C1 to C100 alcohol, preferably a linear or branched C4 to C20 alcohol. Specific examples of preferred solvents include 2-ethyl hexanol, ethylene glycol monobutyl ether, or mixtures thereof.
In another embodiment the fluid optionally comprises an acid forming compound. In a preferred embodiment the acid forming compound comprises an organic or inorganic acid, preferably an organic acid, even more preferably an ester, an anhydride, an acid halide, a polyglycolic acid or a mixture thereof. In a preferred embodiment the acid forming compound comprises methyl formate, ethyl formate, propyl formate, butyl formate, methyl acetate, ethyl acetate, propyl acetate, butyl acetate, ethylene glycol monobutyl acetate, acetic anhydride, acetic formic anhydride, succinic anhydride, tetrachlorophthalic anhydride, chloro ethyl formate, chloro ethyl acetate, chloro, polyglycolic acid and the like and mixtures thereof.
In a preferred embodiment the acid forming compound is present and is methyl formate, ethyl formate, propyl formate and butyl formate and the hydrophilic alcohol if present is methanol, ethanol, propanol or butanol.
In another embodiment the fluid further contains conventional constituents such as corrosion inhibitors, fluid loss additives, gases such as carbon dioxide or nitrogen and the like.
In another embodiment the fluid has a viscosity at 100 secxe2x88x921 of 100 centipoise or more at 100xc2x0 F. (37.8xc2x0 C.). In another embodiment the fluid has a viscosity at 100 secxe2x88x921 of 300 centipoise or more at 100xc2x0 F. (37.8xc2x0 C.). In another embodiment the fluid has a viscosity at 100 secxe2x88x921 of 310 centipoise or more at 100xc2x0 F. (37.8xc2x0 C.). In another embodiment the fluid has a viscosity at 100 secxe2x88x921 of 350 centipoise or more at 200xc2x0 F. (93.3xc2x0 C.). In another embodiment the fluid has a viscosity at 100 secxe2x88x921 of 250 centipoise or more at 150xc2x0 F. (65.6xc2x0 C.). In another embodiment the fluid has a viscosity at 100 secxe2x88x921 of 300 centipoise or more at 150xc2x0 F. (65.6xc2x0 C.). In another embodiment the fluid has a viscosity at 100 secxe2x88x921 of 100 centipoise or more at 180xc2x0 F. (82.2xc2x0 C.). In another embodiment the fluid has a viscosity at 100 secxe2x88x921 of 250 centipoise or more at 180xc2x0 F. (82.2xc2x0 C.). In another embodiment the fluid has a viscosity at 100 secxe2x88x921 of 110 centipoise or more at 280xc2x0 F. (137.8xc2x0 C.).
In another embodiment the fluid has a viscosity at 100 secxe2x88x921 of 100 centipoise or more at 150xc2x0 F. (65.6xc2x0 C.), preferably a viscosity at 100 secxe2x88x921 of 100 centipoise or more at 175xc2x0 F. (79.4xc2x0 C.), even more preferably a viscosity at 100 secxe2x88x921 of 100 centipoise or more at 200 xc2x0 F. (93.3xc2x0 C.), preferably a viscosity at 100 secxe2x88x921 of 100 centipoise or more at 225xc2x0 F. (107.2xc2x0 C.), even more preferably a viscosity at 100 secxe2x88x921 of 100 centipoise or more at 240xc2x0 F. (115.6xc2x0 C.), preferably a viscosity at 100 secxe2x88x921 of 100 centipoise or more at 250xc2x0 F. (121.1xc2x0 C.), even more preferably a viscosity at 100 secxe2x88x921 of 100 centipoise or more at 275xc2x0 F. (135xc2x0 C.), preferably a viscosity at 100 secxe2x88x921 of 100 centipoise or more at 300xc2x0 F. (148.9xc2x0 C.). In a preferred embodiment the fluid has a viscosity at 100 secxe2x88x921 of 100 centipoise or more at 320xc2x0 F. (160xc2x0 C.) and a pH of about 9.
Viscosity is measured by a Fann 50 rheometer using a B5 bob. About 30 ml of fluid is placed in the cup and is pressurized to 500 psig (3.5 MPa) with nitrogen to prevent boiling of the fluid when heated. These instruments may be obtained from Fann Instrument Company, Houston, Tex.
In a preferred embodiment the fluid contains one or more proppant materials. Preferred proppant materials include gravel, sand, resin coated sand, ceramic beads, bauxite, glass, glass beads and the like that have sufficient compressive strength to hold open the fracture once the pressure is released, or mixtures thereof.
The proppants are typically present at amounts of about 1 to 20 pounds of proppant per gallon added (ppa), preferably about 4 to 18 ppa, more preferably 6 to 16 ppa. In another embodiment, the proppant has a mesh size of up to 60 mesh, preferably between 40 to 60 mesh. In another embodiment 10 to 40 mesh is preferred.
The components of the fluid are preferably combined by mixing the surfactants and solvent or solvents and then adding the mixture to water or brine. Then pH is adjusted to the desired level In general the fluids may be prepared in any suitable manner. For example the surfactants may be blended into the water or the solvent to the desired viscosity then the other components are added. The components may be combined in any order of addition. Standard mixing techniques maybe used with or without heat and or agitation.
In a particularly preferred embodiment the well treatment fluid comprises:
(a) lecithin;
(b) water; and
(c) an alcohol and/or a glycol ether,
(d) an acid forming compound, and
(h) a hydrophilic alcohol,
and wherein the composition has a viscosity at 100 secxe2x88x921 of 100 centipoise or more at 150xc2x0 C. and a pH of 6.5 or above.
In a particularly preferred embodiment the fluid comprises lecithin, water, and 2-ethyl-1-hexanol. In a preferred embodiment this composition has a pH of 6.5 or more, preferably between 7 and 12, preferably between 7.5 and 9.5. In another embodiment the water is salt water comprising potassium chloride, sodium chloride, ammonium chloride, calcium chloride, magnesium chloride, or a mixture thereof.
In one embodiment the well treatment fluid of this invention is used to treat and or fracture subterranean formations, particularly petroliferous formations by injecting the fluids described herein into the formation at sufficient pressure to fracture the formation. Sufficient pressures are any pressure above the bottom hole pressure of the well plus friction pressure. Typically the fluid is pumped into a formation at a pressure that will overcome the native overburden pressure of the formation causing fracture.
In another embodiment, the formation has been stabilized with an inorganic water soluble salt capable of inhibiting hydration prior to the fluids described herein being introduced into the formation.